Emulsions containing water-soluble acid retarding agents and methods of making and using

ABSTRACT

Described herein is a multi-phase aqueous composition containing a surfactant; a first phase comprising water, an acid, and a water-soluble acid retarding agent; and a second phase selected from the group consisting of an immiscible organic phase, a gas, and combinations thereof. Further described are methods of making and using such compositions.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. Non-Provisional applicationSer. No. 15/757,423 filed Mar. 5, 2018, now U.S. Pat. No. 11,091,689,which claims the benefit of U.S. Provisional Application Ser. No.62/213,986 filed Sep. 3, 2015 the disclosures of which are incorporatedherein by reference.

BACKGROUND Field

The disclosure relates to emulsions and/or foams containingwater-soluble acid retarding agents, and to methods of making and using.Such emulsions and/or foams including acid-in-oil (A/O) or oil-in-acid(O/A) emulsions.

Description of the Related Art

This section provides background information to facilitate a betterunderstanding of the various aspects of the disclosure. It should beunderstood that the statements in this section of this document are tobe read in this light, and not as admissions of prior art.

Hydrocarbon fluids such as oil and natural gas are obtained from asubterranean geologic formation, commonly referred to as a reservoir, bydrilling a well that penetrates the hydrocarbon-bearing formation. Oncea wellbore is drilled, various forms of well completion components maybe installed in order to control and enhance the efficiency of producingthe various fluids from the reservoir. Well treatment methods often areused to increase hydrocarbon production by using a chemical composition,such as a treatment fluid.

Stimulation operations may be performed to facilitate production offluids from subsurface formations by increasing the net permeability ofa reservoir. There are two main stimulation techniques: matrixstimulation and fracturing. Matrix stimulation is accomplished,typically in sandstone rich formations, by injecting a fluid (e.g., acidor solvent) to dissolve and/or disperse materials that impair wellproduction. Specifically, matrix stimulation may be performed (1) byinjecting chemicals into the wellbore to react with and dissolve thedamage and (2) by injecting chemicals through the wellbore and into theformation to react with and dissolve small portions of the formation tocreate alternative flowpaths for the hydrocarbon (e.g., instead ofremoving the damage, redirecting the migrating oil around the damage).Fracturing involves injecting chemicals through the wellbore and intothe formation at pressures sufficient to actually fracture theformation, thereby creating a large flow channel through whichhydrocarbon can more readily move from the formation and into thewellbore.

In carbonate formations, the goal of matrix stimulation is to createnew, unimpaired flow channels from the formation to the wellbore. Matrixstimulation, typically called matrix acidizing when the stimulationfluid is an acid, generally is used to treat the near-wellbore region.In a matrix acidizing treatment, the acid used (for example hydrochloricacid for carbonates) is injected at a pressure low enough to preventformation fracturing. When injected at low rates into carbonateformations, the acid can form conductive wormholes that extend radiallyfrom the wellbore. Acids can also be injected into subterraneanformation at rates high enough to cause fracturing. In this case, theacid unevenly dissolves the walls of the fracture, so that when theinjection is stopped and the fracture closes, conductive channels to thewell remain.

One of the problems often encountered in the application of acids,especially inorganic acids, at elevated carbonate reservoirtemperatures, is their excessive reaction rate toward carbonateoriginating from a lack of restriction to the mobility of the protons.For example, HCl is very reactive, and at higher temperatures (such as200° F. and higher) and/or low injection rates, favors facialdissolution over wormholing. For this reason, less reactive acidformulations have been pursued. One approach is to use organic acidssuch as formic and acetic acid. Organic acids have higher pKa's thanHCl, but will not completely spend in the reservoir.

Numerous approaches have been applied toward retarding the acidreactivity, mainly via physical means. For example, it is common inoilfield operations to encapsulate inorganic acid into shells of polymergel, linear or crosslinked, or light oils in the presence of surfactantand/or chelating agent. Each of these options offers a certain level ofperformance, but at the same time brings several undesirable sideeffects.

At present, acid treatments are plagued by two primary limitationsnamely, limited radial penetration and severe corrosion to pumping andwellbore tubing. Both effects are associated with thehigher-than-desired reaction rate (or spending rate) of inorganic acids,such as HCl, toward carbonate surface, in particular at highertemperatures. Limitations on radial penetration are caused by the factthat as soon as the acid, in particular inorganic acids, such as bynonlimiting example, HCl, is introduced into the formation or wellbore,it reacts instantaneously with the formation matrix and/or the wellborescaling. In practice, the dissolution is so rapid that the injected acidis spent by the time it reaches no more than a few inches beyond thewellbore, incapable of generating much desired fracture length far fromthe wellbore. Organic acids (e.g., formic acid, acetic acid and/orlactic acid and its polymeric version) are sometimes used to addresslimitations on radial penetration since organic acids react more slowlythan inorganic acids. Increasingly, retarded acid systems, which usetechniques such as gelling the acid or oil-wetting the formation, areused. Each of such alternatives, however, has associated drawbacks andis an imperfect solution to limited radial penetration.

Other limitations related to the use of acids are: 1) very highmiscibility of acids with water when the potential for undesirablemigration of the acid-bearing fluid into a water-saturated zone is aconcern; and 2) iron precipitation, especially in sour wells, where theiron sulfide scale formed in boreholes, tubulars, and/or formations isdissolved by the acid with the formation of hydrogen sulfide (H₂S) andundesirable iron precipitates such as ferric hydroxide or ferroussulfide that affect the permeability of the formation. Therefore, acidtreatment fluids often contain additives to minimize iron precipitationand H₂S evolution, for example by sequestering the iron ions insolution, or by reducing ferric ions to the more soluble ferrous form ofiron.

The performance of a fracture acidizing treatment job may be measured bythe length of the fracture that is effectively acidized. The distance areactive acid travels along the fracture (e.g., acid penetration depth),is governed by the acid flow (injection) rate and the acid reaction(spending) rate at the rock surface. In most of the circumstancesencountered in acid treatment, the reaction rate between acid and rockis very fast, and the rate determining step is acid mass transfer frombulk to rock surface.

In fracture acidizing, the treatment fluid used is injected at apressure high enough to cause formation fracturing, designed to opensustained flowpath network that connects limestone and/or dolomitereservoirs to the wellbore. In order to achieve deeper penetration infracture acidizing, it is often desirable to retard the acid in suchtreatments as well. Common approaches to acid retardation for fractureacidizing include gelling and to a minor extent chemical intervention.Each of these methodologies brings certain advantages that areinvariably accompanied by a set of disadvantages. For example, gelledacids provide moderate retardation in the temperature range of 80 to200° F. As gels exhibit high viscosity and low friction loss, theyfunction primarily as diverting agents, contributing to fluid lossreduction. It is also common practice to retard acid using surfactants,although limited acid retardation is obtained. However, the deploymentof surfactant alone also carries a few unwanted effects. For example, itcould strip any existing coating on carbonate surfaces and as such actas an accelerator. Therefore, retardation schemes relying on surfactantfilms are often unreliable and ineffective. Furthermore, the attempt touse biodegradable, solid acid precursors such as polylactic acid inacidizing treatments has been plagued by the intrinsic disadvantage ofvery small acid capacity, leading to prohibitive costs and cumbersomedependency on formation temperature range which governs the rate ofdegradation.

SUMMARY

This summary is provided to introduce a selection of concepts that arefurther described below in the detailed description. This summary is notintended to identify key or essential features of the claimed subjectmatter, nor is it intended to be used as an aid in limiting the scope ofthe claimed subject matter.

In a first aspect of the disclosure, a multi-phase aqueouscomposition(s) include: a surfactant; a first phase including water, anacid, and a water-soluble acid retarding agent; and a second phaseselected from the group consisting of an immiscible organic phase, agas, and combinations thereof.

In another aspect of the disclosure, method(s) include treating asubterranean formation fluidly coupled to a wellbore with a treatmentfluid including the multi-phase aqueous composition.

In another aspect of the disclosure, method(s) include: treating asubterranean formation fluidly coupled to a wellbore with a treatmentfluid including a multi-phase aqueous composition containing: asurfactant including a foaming agent; a first phase including water, anacid, and a water-soluble acid retarding agent; and a second phaseincluding a gas selected from the group consisting of nitrogen, carbondioxide, oxygen, helium, argon, hydrogen, methane or ethane, or acombination thereof; wherein the multi-phase aqueous composition is inthe form of a foam.

BRIEF DESCRIPTION OF THE DRAWINGS

Certain embodiments of the disclosure will hereafter be described withreference to the accompanying drawings, wherein like reference numeralsdenote like elements. It should be understood, however, that theaccompanying figures illustrate the various implementations describedherein and are not meant to limit the scope of various technologiesdescribed herein, and:

FIG. 1 depicts an example of equipment used to treat a wellbore and/or aformation fluidly coupled to the wellbore according to some embodimentsof the disclosure;

FIG. 2 shows pore volumes to break through versus interstitial velocitycurves for aqueous acid solutions based upon tests performed at 70° F.,according to the disclosure;

FIG. 3 shows pore volumes to break through versus interstitial velocitycurves for aqueous acid solutions based upon tests performed at 200° F.,according to the disclosure;

FIGS. 4A-4E depict face dissolution of core samples evaluated inaccordance with the disclosure; and,

FIG. 5 shows calcium generation concentration versus time curves forsome aqueous acid solutions evaluated, according to the disclosure.

DETAILED DESCRIPTION

The following description of the variations is merely illustrative innature and is in no way intended to limit the scope of the disclosure,its application, or uses. The description and examples are presentedherein solely for the purpose of illustrating the various embodiments ofthe disclosure and should not be construed as a limitation to the scopeand applicability of the disclosure. While the compositions of thepresent disclosure are described herein as comprising certain materials,it should be understood that the composition could optionally comprisetwo or more chemically different materials. In addition, the compositioncan also comprise some components other than the ones already cited. Inthe summary of the disclosure and this detailed description, eachnumerical value should be read once as modified by the term “about”(unless already expressly so modified), and then read again as not somodified unless otherwise indicated in context. Also, in the summary ofthe disclosure and this detailed description, it should be understoodthat a concentration or amount range listed or described as beinguseful, suitable, or the like, is intended that any and everyconcentration or amount within the range, including the end points, isto be considered as having been stated. For example, “a range of from 1to 10” is to be read as indicating each and every possible number alongthe continuum between about 1 and about 10. Thus, even if specific datapoints within the range, or even no data points within the range, areexplicitly identified or refer to only a few specific, it is to beunderstood that inventors appreciate and understand that any and alldata points within the range are to be considered to have beenspecified, and that inventors had possession of the entire range and allpoints within the range.

Unless expressly stated to the contrary, “or” refers to an inclusive orand not to an exclusive or. For example, a condition A or B is satisfiedby anyone of the following: A is true (or present) and B is false (ornot present), A is false (or not present) and B is true (or present),and both A and B are true (or present).

In addition, use of the “a” or “an” are employed to describe elementsand components of the embodiments herein. This is done merely forconvenience and to give a general sense of concepts according to thedisclosure. This description should be read to include one or at leastone and the singular also includes the plural unless otherwise stated.

The terminology and phraseology used herein is for descriptive purposesand should not be construed as limiting in scope. Language such as“including,” “comprising,” “having,” “containing,” or “involving,” andvariations thereof, is intended to be broad and encompass the subjectmatter listed thereafter, equivalents, and additional subject matter notrecited.

Also, as used herein any references to “one embodiment” or “anembodiment” means that a particular element, feature, structure, orcharacteristic described in connection with the embodiment is includedin at least one embodiment. The appearances of the phrase “in oneembodiment” in various places in the specification are not necessarilyreferring to the same embodiment.

The terms “formation” or “subterranean formation” as utilized hereinshould be understood broadly, and are used interchangeably. A formationincludes any underground fluidly porous formation, and can includewithout limitation any oil, gas, condensate, mixed hydrocarbons,paraffin, kerogen, water, and/or CO₂ accepting or providing formations.A formation can be fluidly coupled to a wellbore, which may be aninjector well, a producer well, and/or a fluid storage well. Thewellbore may penetrate the formation vertically, horizontally, in adeviated orientation, or combinations of these. The formation mayinclude any geology, including at least a sandstone, limestone,dolomite, shale, tar sand, and/or unconsolidated formation. The wellboremay be an individual wellbore and/or a part of a set of wellboresdirectionally deviated from a number of close proximity surfacewellbores (e.g. off a pad or rig) or single initiating wellbore thatdivides into multiple wellbores below the surface.

The term “oilfield treatment fluid” as utilized herein should beunderstood broadly. In certain embodiments, an oilfield treatment fluidincludes any fluid having utility in an oilfield type application,including a gas, oil, geothermal, or injector well. In certainembodiments, an oilfield treatment fluid includes any fluid havingutility in any formation or wellbore described herein. In certainembodiments, an oilfield treatment fluid includes a matrix acidizingfluid, a wellbore cleanup fluid, a pickling fluid, a near wellboredamage cleanup fluid, a surfactant treatment fluid, an unviscosifiedfracture fluid (e.g. slick water fracture fluid), and/or any other fluidconsistent with the fluids otherwise described herein. An oilfieldtreatment fluid may include any type of additive known in the art, whichare not listed herein for purposes of clarity of the presentdescription, but which may include at least friction reducers,inhibitors, surfactants and/or wetting agents, fluid diverting agents,particulates, acid retarders (except where otherwise provided herein),organic acids, chelating agents, energizing agents (e.g. CO₂ or N₂), gasgenerating agents, solvents, emulsifying agents, flowback controlagents, resins, breakers, and/or non-polysaccharide based viscosifyingagents.

The term “high pressure pump” as utilized herein should be understoodbroadly. In certain embodiments, a high pressure pump includes apositive displacement pump that provides an oilfield relevant pumpingrate—for example at least 0.5 barrels per minute (bpm), although thespecific example is not limiting. A high pressure pump includes a pumpcapable of pumping fluids at an oilfield relevant pressure, including atleast 500 psi, at least 1,000 psi, at least 2,000 psi, at least 5,000psi, at least 10,000 psi, up to 15,000 psi, and/or at even greaterpressures. Pumps suitable for oilfield cementing, matrix acidizing,and/or hydraulic fracturing treatments are available as high pressurepumps, although other pumps may be utilized.

The term “treatment concentration” as utilized herein should beunderstood broadly. A treatment concentration in the context of an HClconcentration is a final concentration of the fluid before the fluid ispositioned in the wellbore and/or the formation for the treatment, andcan be any concentration necessary to provide sufficient acidicfunction. The treatment concentration may be the mix concentrationavailable from the HCl containing fluid at the wellsite or otherlocation where the fluid is provided from. The treatment concentrationmay be modified by dilution before the treating and/or during thetreating. Additionally, the treatment concentration may be modified bythe provision of additives to the fluid. In certain embodiments, atreatment concentration is determined upstream of additives delivery(e.g. at a blender, hopper, or mixing tub) and the concentration changefrom the addition of the additives is ignored. In certain embodiments,the treatment concentration is a liquid phase or acid phaseconcentration of a portion of the final fluid—for example when the fluidis an energized or emulsified fluid.

Multi-phase aqueous compositions described below and useful inaccordance with the disclosure exhibit a retarded acid reactivity thatfacilitates greater depth of fracture and/or matrix acidizing. Themulti-phase aqueous composition can comprise, consist of, or consistessentially of: a surfactant; a first phase comprising water, an acid,and a water-soluble acid retarding agent; and a second phase selectedfrom the group consisting of an immiscible organic phase, a gas, andcombinations thereof.

The acid in the first phase can be selected from the group consisting ofhydrochloric acid (HCl), nitric acid, phosphoric acid, sulfuric acid,hydrofluoric acid, hydrobromic acid, perchloric acid, hydrogen iodide,alkanesulfonic acids, arylsulfonic acids, acetic acid, formic acid,alkyl carboxylic acids, acrylic acid, lactic acid, glycolic acid,malonic acid, fumaric acid, citric acid, tartaric acid, or theirderivatives, and mixtures thereof. Generally, an acid is transported toa wellsite. According to some embodiments, the acid is present in themulti-phase aqueous compositions in an amount up to about 36 wt %, orfrom about 7.5 to about 36 wt %, or from about 7.5 to about 28 wt %, orfrom about 7.5 to about 20 wt %, based on the total weight of thecomposition. In some other embodiments, acid is present in themulti-phase aqueous compositions in an amount of at least about 37 wt %,

In some embodiments, an acid that has shown particular utility in themulti-phase aqueous composition(s) according to the disclosure ishydrochloric acid. In some other embodiments, the multi-phase aqueouscomposition may include an amount of hydrofluoric acid (HF). HF exhibitsdistinct reactions from HCl, and is useful in certain applications toenhance the activity of the resulting multi-phase aqueous solution. Forexample, HF is utilized in the cleanup of sandstone formations where HClalone is not effective for removing certain types of formation damage.It is believed that the present multi-phase aqueous solution will haveeffects with HF similarly to the observed effects with HCl. Accordingly,multi-phase solutions can be formulated with a total acid amount that ismuch higher than presently attainable formulations. In yet anotherembodiment, the HF is present in the multi-phase aqueous composition inan amount of at least 0.25% by weight. The HF may be present in additionto the amount of HCl, and/or as a substitution for an amount of the HCl.

The water-soluble acid retarding agent has utility in retarding the rateat which the acid solution reacts with carbonate-mineral, or othersurfaces inside the formation. Thus, the water-soluble acid retardingagent may slow the reactivity of the acid towards the carbonate-mineralsurfaces, without compromising its acid capacity. Such retardation isuseful in the context of stimulating or improving production fromsubterranean formations that contain hydrocarbons, steam, geothermalbrines and other valuable materials as known in the art. Slowing therate of reaction may allow deeper penetration of the acid into thesubterranean formations than regular acid, thereby increasing theformation permeability and productivity. Water-soluble acid retardingagents, as used herein, includes any water-soluble material that reducesacid activity through a mechanism other than mere dilution. Thewater-soluble retarding agents of the first phase can be selected fromthe group consisting of a salt, urea or one if its derivatives, analpha-amino acid, a beta-amino acid, a gamma-amino acid, an alcohol withone to five carbons, a surfactant having a structure in accordance withFormula I, and combinations thereof:

in which R₁ is a hydrocarbyl group that may be branched or straightchained, aromatic, aliphatic or olefinic and contains from about 1 toabout 26 carbon atoms and may include an amine; R₂ is hydrogen or analkyl group having from 1 to about 4 carbon atoms; R₃ is a hydrocarbylgroup having from 1 to about 5 carbon atoms; and Y is an electronwithdrawing group.

Such salt(s) can comprise: i) a cation selected from the groupconsisting of lithium, sodium, potassium, rubidium, cesium, beryllium,magnesium, calcium, strontium, barium, scandium, yttrium, titanium,zirconium, hafnium, vanadium, niobium, tantalum, chromium, molybdenum,tungsten, manganese, technetium, rhenium, iron, ruthenium, osmium,cobalt, rhodium, iridium, nickel, palladium, platinum, copper, silver,gold, zinc, cadmium, mercury, boron, aluminum, gallium, indium,thallium, tin, ammonium, alkylammonium, dialkylammonium,trialkylammonium and tetraalkylammonium, and combinations thereof; andii) an anion selected from the group consisting of fluoride, chloride,bromide, iodide, sulfate, bisulfate, sulfite, bisulfite nitrate,alkanesulfonates, arylsulfonates, acetate, formate, and combinationsthereof

The amount of water-soluble acid retarding agent(s) present in thecomposition can be any concentration necessary to provide sufficientacid retardation function. According to the present embodiments, thewater-soluble acid retarding agent(s) is added to the first phase of themulti-phase aqueous composition in an amount up to its solubility limitin the first phase. According to some embodiments, the water-solubleacid retarding agent is present in the multi-phase aqueous compositionsin an amount of up to about 40 wt %, from about 1 to about 40 wt %, fromabout 5 to about 35 wt %, or from about 5 to about 20 wt %, based on thetotal weight of the multi-phase aqueous composition.

In some embodiments, the first phase of the multi-phase aqueouscomposition may include HCl as the acid in a weight fraction exceeding37%, based on the total weight of the composition. The water-solubleacid retarding agent present in some multi-phase aqueous compositionsuseful in accordance with the disclosure allows the HCl fraction toexceed the 37% normally understood to be the limit of HCl solubility atatmospheric pressure. Such water-soluble acid retarding agents includeat least one salt compound and urea, or urea derivative. Above 37%,normally, the evolution of HCl gas from the solution prevents the HClfraction from getting any higher. In one or more embodiments, the HClweight fraction of the multi-phase aqueous solution may be as high as45.7 wt %.

Without being bound by any particular theory, inventors envisagemechanisms that inhibit acid activity. The first involves the disruptionof the hydrogen-bonded network of water. In the Grotthuss proton-hoppingmechanism, protons move in water not through Brownian motion, but rathercharge transport through shifting hydrogen bonds. Solutes are known todisrupt the Grotthuss mechanism by interacting with water themselves,rather than allowing protons to associate freely. This slows the protontransport to the wormhole wall during a matrix acidizing treatment. Theintroduction of solutes such as the water-soluble acid retardingagent(s) also has a similar second effect by simply replacing water. Thelack of water molecules crowds the fluid and limits the diffusion ofprotons.

A second mechanism involves the dissociation of acids in solution. Asmentioned, organic acids have higher pKa's than HCl, making the protonsfrom these acids less available for reaction. In some aspects of thedisclosure, compounds that lower the polarizability (as indicated by thedielectric constant) of water are used, which therefore decrease theproton dissociation of acids. It is believed that aqueous solutes canmodify the activity of acids in water in one or both of thesemechanisms.

A parameter that quantifies the retardation of the acid is theretardation factor. As described herein, the retardation factorindicates the ratio of apparent surface reaction rates. According to thepresent embodiments, the retardation factor of the multi-phase aqueouscomposition is higher or equal to a retardation factor of a secondsolution of acid of a same concentration as the acid comprised in themulti-phase aqueous composition without the water-soluble acid retardingagent. For example, in various embodiments, the multi-phase aqueouscomposition may exhibit an acid retardation factor higher than or equalto about 3, at least about 5, or at least about 11 at about 70° F. Atabout 200° F., the composition may exhibit an acid retardation factorhigher than or equal to about 3, higher than or equal to about 5, oreven higher than or equal to about 7.

Water can be present in the first phase of the multi-phase aqueouscomposition in an amount sufficient to dissolve the acid and thewater-soluble acid retarding agent. According to embodiments accordingto the disclosure, the water concentration included in the multi-phaseaqueous composition may be greater than 0 wt % and lower or equal to 80wt %, based on the total weight of the multi-phase aqueous composition.In various embodiments, the water concentration may be lower than 60 wt%, or lower than 40 wt % or lower than 20 wt %, and equal to or higherthan 8 wt %, or equal to or higher than 10 wt %, or lower than 8 wt %,based on the total weight of the multi-phase aqueous composition.

According to some embodiments, an amount of water is mixed with awater-soluble acid retarding agent, where the amount of water is presentin an amount between 0.3 and 5 times the mass of the water-soluble acidretarding agent, where any lower limit can be 0.35, 0.4, or 0.45 and anyupper limit can be 1.0, 1.2, 1.25, where any lower limit can be combinedwith any upper limit. The procedure further includes dissolving anamount of acid into the combined amount of water and water-soluble acidretarding agent in the first phase. The acid, such as HCl, may be addedby any method, such as bubbling HCl gas through the solution. Thedissolving of the HCl may occur after dissolving of the water-solubleacid retarding agent, simultaneous with the dissolving of thewater-soluble acid retarding agent, or at least partially before thedissolving of the water-soluble acid retarding agent. The amount of HClgas is in a molar ratio of between 4.0 and 0.5 times the amount of thewater-soluble acid retarding agent. In yet another embodiment, theprocedure includes dissolution of at least a portion of thewater-soluble acid retarding agent in the water during the dissolutionof the HCl in the combined water and water-soluble acid retarding agent.Example operations include beginning the dissolution of the HCl andadding the water-soluble acid retarding agent as a solid or a solution,providing some of the water-soluble acid retarding agent in solutionwith the water and some of the water-soluble acid retarding agent as asolid, and/or providing the water-soluble acid retarding agent as asolid in the water and dissolving the HCl into the water whiledissolving the water-soluble acid retarding agent.

According to some embodiments, the gas can be selected from the groupconsisting of nitrogen, carbon dioxide, oxygen, helium, argon, hydrogen,methane or ethane, or a combination thereof. According to someembodiments, the immiscible organic phase can be any organic material atleast partially immiscible in water. The immiscible organic phase can beselected from the group consisting of alkanes, cycloalkanes, aromaticcompounds, heteroaromatic compounds, and combinations thereof.

The foaming agent can be selected from the group consisting of anethoxylated nonionic surfactant, a cationic surfactant, an anionicsurfactant, a zwitterionic surfactant and combinations thereof.

According to some embodiments, the multi-phase aqueous composition canbe in the form of a foam. In such embodiments, and in other embodiments,the surfactant can be the foaming agent and the second phase cancomprise the gas.

According to some embodiments, the second phase comprises the immiscibleorganic phase and the multi-phase aqueous composition can be in the formof an emulsion where the first phase is a continuous phase and thesecond phase is a discontinuous phase and is stabilized by thesurfactant, referred to as an oil in acid (O/A) emulsion. In suchembodiments, the surfactant can be an ethoxylated nonionic surfactant ofthe structure RO(CH₂CH₂O)_(n)H, where R can be any alkyl group of 6 to18 carbons, and 1≤n≤10. The multi-phase aqueous composition in the formof an O/A emulsion can be pumped through a wellbore and into asubterranean carbonate containing formation at a rate at which theformation does not fracture. In accordance with some embodiments, theformation bears petroleum deposits, potentially with precipitatedparaffins or asphaltenes that are causing formation damage. Themulti-phase aqueous composition in the form of an O/A emulsion canperform two functions as it enters the formation of interest. It cancreate a conductive wormhole, longer than an unretarded acid would in amatrix acidizing treatment. Also, the internal oil phase will dissolvethe organic damage, also improving production.

According to some embodiments, the second phase comprises the immiscibleorganic phase and the multi-phase aqueous composition can be in the formof an emulsion where the second phase is a continuous phase and thefirst phase is a discontinuous phase and is stabilized by thesurfactant, referred to as an acid in oil (A/O) emulsion. In suchembodiments, the surfactant can be a cationic surfactant of thestructure [RNXYZ]⁺ A⁻, where R is an alkyl chain of 10 to 18 carbons. X,Y and Z are selected from the group consisting of methyl, ethyl,hydroxyethyl or benzyl. X, Y and Z can be the same or different. A is ananion selected from the group consisting of fluoride, chloride, bromide,iodide, acetate, sulfate, alkylsulfonate or arylsulfonate. Themulti-phase aqueous composition in the form of an A/O emulsion can bepumped through a wellbore and into a subterranean carbonate containingformation at a rate that will not create enough pressure to fracture theformation. As the emulsified acid enters the formation, conductivewormholes are formed that extend radially from the wellbore. Normalizedto treatment volume, wormholes formed from emulsified acids and acidswith water-soluble retarding agents tend to extend farther than thosefrom straight acid. A combination of the two chemistries is expected toimprove wormhole penetration even further.

In accordance with some embodiments, the multi-phase aqueous compositionin the form of an A/O emulsion can be pumped into the carbonateformation at rates that are high enough to create a fracture in theformation. The emulsified acid flows into the fracture, growing itslength and height while dissolving conductive channels that createpathways from the distal parts of the formation to the wellbore. The A/Oemulsion will prevent leak-off of the acid into the formation, meaningthat more acid will be spent on the fracture surface. The water-solubleretarding agent will slow the reaction of HCl with fracture surface andcarve out longer channels in the fracture.

In accordance with some embodiments, method(s) can comprise, consist of,or consist essentially of providing the multi-phase aqueouscompositions, as described herein, and treating a formation fluidlycoupled to a wellbore with an oilfield treatment fluid comprising themulti-phase aqueous composition.

In accordance with some embodiments, the multi-phase aqueous compositioncan be in the form of a foam prepared by: introducing the acid, thewater-soluble retarding agent and the foaming agent into a carbonateformation, reacting the acid with the carbonate formation, generatingcarbon dioxide, entraining the carbon dioxide into the foaming agent ofthe multi-phase aqueous composition, creating a low-density foam thatwill help lift the spent (reduced acid content) multi-phase aqueouscomposition from the formation of the well and aid in returning the wellto production. Additionally, if the formation already contains gases,such as low molecular weight hydrocarbons (methane, ethane, propane,etc), hydrogen sulfide or carbon dioxide, these can also form part ofthe foam.

In accordance with some embodiments, method(s) can comprise, consist of,or consist essentially of treating a formation fluidly coupled to awellbore with an oilfield treatment fluid comprising the multi-phaseaqueous composition(s) in the form of a foam, as described inembodiments herein, where the surfactant comprises a foaming agent, andthe second phase comprises the gas. At pumping rates high enough tofracture the formation, the multi-phase aqueous composition in the formof a foam can enter the fracture, but not much of the fluid in such foamwill enter the porous medium composing the walls of the fracture. Theacid's reaction rate has also been retarded, and coupled with lowerlosses to the formation, should create a stimulated zone that extendsfurther from the wellbore.

In accordance with some embodiments, the multi-phase aqueous compositionin the form of a foam can be used to divert fluids from a highpermeability zone to low permeability zone in the reservoir. Themulti-phase aqueous composition in the form of a foam can create highpressure drop due to multiphase flow in the porous media. This excessivepressure build up in the wellbore helps in diverting acid to lowpermeability zones. In some embodiments, injecting the multi-phaseaqueous composition in the form of a foam below the fracture pressure ofthe reservoir will allow the multi-phase aqueous composition in the formof a foam to enter the formation and penetrate farther into thereservoir than a regular acid treatment. The pressure build up will helpin diverting a part of the multi-phase aqueous composition in the formof a foam into the low permeability zone. The resulting treatment willhave deeper acid penetration in both low and high permeability zonescompared to a regular acid treatment.

In some embodiments, the multi-phase aqueous composition in the form ofa foam can also be formed by: i) introducing the surfactant and thefirst phase into the formation, and ii) separately introducing the gasinto the formation for contact with the surfactant and the first phasewith sufficient energy to form the multi-phase aqueous composition inthe form of a foam.

Further, it is also within the scope of the present disclosure that themulti-phase aqueous compositions may be combined with one or more otheradditives known to those of skill in the art, such as, but not limitedto, corrosion inhibitors, scale inhibitors, foaming agents, hydrogensulfide scavengers, reducing agents and/or chelants, and the like.

The corrosion inhibitor is typically provided in liquid form and ismixed with the other components of the treatment fluid at the surfaceand then introduced into the formation. The corrosion inhibitor systemis present in the treatment fluid in an amount of from about 0.2% toabout 5% or about 0.2% to about 3% by total weight of the treatmentfluid. The corrosion inhibitor used with the fluids of the presentdisclosure includes an alkyl, alkenyl, alycyclic or aromatic substitutedaliphatic ketone, which includes alkenyl phenones, or an aliphatic oraromatic aldehyde, which includes alpha, or beta-unsaturated aldehydes,or a combination of these. Alkyl, alycyclic or aromatic phenone andaromatic aldehyde compounds may also be used in certain applications.Other unsaturated ketones or unsaturated aldehydes may also be used.Alkynol phenone, aromatic and acetylenic alcohols and quaternary ammoniacompounds, and mixtures of these may be used, as well. These may bedispersed in a suitable solvent, such as an alcohol, and may furtherinclude a dispersing agent and other additives.

Chelating agents are materials that are employed, among other uses, tocontrol undesirable reactions of metal ions. In oilfield chemicaltreatments, chelating agents are frequently added to matrix stimulationacids to prevent precipitation of solids (metal control) as the acidsspend on the formation being treated. These precipitates include ironhydroxide and iron sulfide. In addition, chelating agents are used ascomponents in many scale removal/prevention formulations. Two differenttypes of chelating agents may be used: polycarboxylic acids (includingaminocarboxylic acids and polyaminopolycarboxylic acids) andphosphonates. The non-surface active substituted ammonium containingaminoacid derivatives may act as chelating agents when present in thetreatment fluid in amount of from about 0.05% to about 10% or from about1 wt % to about 5 wt %, based upon total weight percent of the treatmentfluid.

Some embodiments according to present disclosure are methods fortreating a formation penetrated by a wellbore. The methods involveproviding an oilfield treatment fluid including the multi-phase aqueouscomposition(s) described in this disclosure to a high pressure pump andoperating the high pressure pump to treat at least one of a wellbore andthe formation fluidly coupled to the wellbore. The operation of the pumpmay include at least one of (i) injecting the oilfield treatment fluidinto the formation at matrix rates; (ii) injecting the oilfieldtreatment fluid into the formation at a pressure equal to a pressurethat fractures the formation; and (iii) contacting at least one of thewellbore and the formation with the oilfield treatment fluid.

Referring now to FIG. 1, a system 100 used to treat a wellbore 106and/or a formation 108 fluidly coupled to the wellbore 106 is depicted.The formation 108 may be any type of formation with a bottom holetemperature up to about 204° C. (400° F.). In various embodiments thetemperature is at least 38° C. (100° F.). The temperature may also rangefrom about 38° C. to about 204° C. The wellbore 106 is depicted as avertical, cased and cemented wellbore 106, having perforations providingfluid communication between the formation 108 and the interior of thewellbore 106. However, the particular features of the wellbore 106 arenot limiting, and the example provides an example context 100 for aprocedure.

The system 100 includes a high-pressure pump 104 having a source of themulti-phase aqueous composition 102, as described herein. The highpressure pump 104 is fluidly coupled to the wellbore 106, through highpressure lines 120 in the example. The example system 100 includestubing 126 in the wellbore 106. The tubing 126 is optional andnon-limiting. In various embodiments, the tubing 106 may be omitted, acoiled tubing unit (not shown) may be present, and/or the high pressurepump 104 may be fluidly coupled to the casing or annulus 128. The tubingor casing may be made of steel.

Certain additives (not shown) may be added to the multi-phase aqueouscomposition 102 to provide, or as a part of, an oilfield treatmentfluid. Additives may be added at a blender (not shown), at a mixing tubof the high pressure pump 104, and/or by any other method. In one ormore embodiments, a second fluid 110 may be a diluting fluid, and themulti-phase aqueous composition 102 combined with some amount of thesecond fluid 110 may make up the oilfield treatment fluid. The dilutingfluid may contain no acid, and/or acid at a lower concentration than themulti-phase aqueous composition 102. The second fluid 110 mayadditionally include any other materials to be added to the oilfieldtreatment fluid, including additional amounts of a water-soluble acidretarding agent. In certain embodiments, an additional water-solubleacid retarding agent solution 112 is present and may be added to themulti-phase aqueous composition 102 during a portion when themulti-phase aqueous composition 102 is being utilized. The additionalwater-soluble acid retarding agent solution 112 may include the same ora different water-soluble acid retarding agent from the multi-phaseaqueous composition 102, and/or may include water-soluble acid retardingagent at a distinct concentration from the multi-phase aqueouscomposition.

The high pressure pump 104 can treat the wellbore 106 and/or theformation 108, for example by positioning fluid therein, by injectingthe fluid into the wellbore 106, and/or by injecting the fluid into theformation 108. Example and non-limiting operations include any oilfieldtreatment without limitation. Potential fluid flows include flowing fromthe high-pressure pump 104 into the tubing 126, into the formation 108,and/or into the annulus 128. The fluid may be recirculated out of thewell before entering the formation 108, for example utilizing a backside pump 114. Referring still to FIG. 1, the annulus 128 is shown influid communication with the tubing 126. In various embodiments, theannulus 128 and the tubing 126 may be isolated (e.g. with a packer).Another example fluid flow includes flowing the oilfield treatment fluidinto the formation at a matrix rate (e.g. a rate at which the formationis able to accept fluid flow through normal porous flow), and/or at arate that produces a pressure exceeding a hydraulic fracturing pressure.The fluid flow into the formation may be either flowed back out of theformation, and/or flushed away from the near wellbore area with a followup fluid. Fluid flowed to the formation may be flowed to a pit orcontainment (not shown), back into a fluid tank, prepared for treatment,and/or managed in any other manner known in the art. Acid remaining inthe returning fluid may be recovered or neutralized.

Another example fluid flow includes the multi-phase aqueous composition102 including an acid and water-soluble acid retarding agent. Theexample fluid flow includes a second aqueous solution 116 includingwater-soluble acid retarding agent. The fluid flow includes,sequentially, a first high pressure pump 104 and a second high pressurepump 118 treating the formation 108. As seen in FIG. 1, the secondhigh-pressure pump 118 is fluidly coupled to the tubing 126 through asecond high pressure line 122. The fluid delivery arrangement isoptional and non-limiting. In one embodiment, a single pump may deliverboth the multi-phase aqueous solution 102 and the second aqueoussolution 116. In yet another example, either the multi-phase aqueoussolution 102 or the second aqueous solution 116 may be delivered first,and one or more of the solutions 102, 116 may be delivered in multiplestages, including potentially some stages where the solutions 102, 116are mixed.

The following examples are presented to further illustrate thepreparation and properties of the wellbore fluids of the presentdisclosure and should not be construed to limit the scope of thedisclosure, unless otherwise expressly indicated in the appended claims.

EXAMPLES

Emulsions were prepared from an aqueous phase containing hydrochloricacid (15% w/v, that is, 15 g HCl/100 ml water) and a water-solubleretarding agent (19% w/v, either magnesium chloride or urea) and adiesel fuel organic phase. The emulsions were ˜70% aqueous phase and˜30% organic phase by volume. Different surfactants useful for i)creating an acid-in-oil (A/O) emulsion, and ii) creating an oil-in-acid(O/A) emulsion, were added at 0.5% to create and stabilize theemulsions. In this non-limiting example, the A/O emulsion is stabilizedby a cationic surfactant and the O/A emulsion is stabilized by anethoxylated nonionic surfactant. The mixtures were homogenized byvigorous shaking, and allowed to stand. The A/O emulsions (containingeither magnesium chloride or urea) separated ˜10% of their volume as topoil. Both required over one hour for separation, indicating a verystable emulsion. The O/A emulsions containing magnesium chloride andurea in the aqueous phase required 22 minutes and 15 minutes,respectively, to fully separate.

Various formulations were prepared using different retarding agents andHCl as the acid. A series of tests were conducted to evaluate theseformulations. To fully assess the properties of the preparedformulations, the tests were conducted in an autoclave under up to 3000psi hydrostatic pressure, with the thermal energy transmitted through asilicone oil bath. To determine the retardation factor (RF) of certainadditives, formation response tests were conducted with different acidformulations. In the experiments, Indiana limestone cores, which were 1inch in diameter by 6 inches in length, were held at ˜2800 psi confiningpressure to ensure that no fluids channeled around the sides, and wereheated to desired temperature. The acid fluids were flowed through thecore, with a ˜1200 psi back pressure, which were conditions provided sothe acid will preferentially form wormholes. When the wormhole extendedthe entire length of the core, the pressure drops across the coreapproached zero, which was indicative that the fluid was no longerflowing through porous medium, but rather what approximated a tortuouspipe.

The number of pore volumes of fluid required to create the wormholes wasa function of the acid injection velocity (u_(i), FIGS. 2 and 3). Theoptimal injection velocity (u_(i-opt)) is that which requires the lowestnumber of pore volumes for the wormhole to break through the core. Usingthis approach, pore volume to break through (PVBT) curves versusinterstitial velocity curves were generated and the u_(i-opt) and RFcalculated for each acid formulation (Table 1) at 70° F. (FIG. 2) and200° F. (FIG. 3).

TABLE 1 Retardation Factors of Acid Formulations Retarding AgentEsitmated Temperature Retarding Agent concentration retardation Entry (°F.) Additive (% by weight) factor (RF) 1 70 none — — 2 urea 18.5 3.3 3N, N′-dimethyl 27 5.8 urea (DMU) 4 MgC1₂ 19 10.9 5 200 none — — 6 urea18.5 1.3 7 MgC1₂ 19 3.1

The estimated retardation factor was calculated according to thefollowing equation:

$RF_{x}\text{∼}\left( \frac{u_{{i - {opt}},{HCl}}}{u_{{i - {opt}},x}} \right)^{2}$

All aqueous fluids evaluated contained hydrochloric acid (15%weight/volume) and a corrosion inhibitor (0.6% by volume). The resultsdemonstrate that compounds which disrupt the hydrogen bonding network ofwater and its dielectric constant are able to retard the activity ofacid in subterranean formations. In particular, magnesium chloride(MgCl₂) used as a retarding agent showed significant retardation atsimilar or lower concentrations than the other retarding evaluated.

Wormholes in carbonate formations can acquire different structuresdepending on the rate of acid injection. At very low injection rates,there is no wormhole at all, as only the face of the formationdissolves. Wormholes that do form at low injection rates tend to bebroad and conical. Close to the optimum injection rate, a dominant,narrow wormhole forms with a small amount of branching. When theinjection rate is increased past the optimum injection rate, the acid isforced into less permeable zones and creates a ramified (highlybranched) wormhole. Ramified structures will transition to uniformlydissolved rock at very high injection rates. By comparing thecharacteristics of the injection face of the cores from the acidinjection experiment described in evaluations above, estimates of thewormhole characteristics can be made. Table 2 provides the low acidinjection rates, break through times and pore volumes, from theevaluations above at 200° F., and FIGS. 4A-4C graphically illustrate thecore face images and break through characteristics at low acid injectionrates at 200° F.

TABLE 2 Core face images and break through characteristics at low acidinjection rates 200° F. 15% HCl + 15% HCl + Fluid => 15% HCl 18.5% urea19% MgCl₂ Injection rate (ml/min) 0.2 0.3 0.2 Break throughtime >3:30 >1:30 0:34 (h:mm) Pore volumes to break >3.4 >3 0.53 through

In the tests performed at 200° F., the core faces treated with 15% HCl(FIG. 4A) and 15% HCl with urea (FIG. 4B), both showed a large amount ofcore facial dissolution 402 and developing conical wormholes 404. Inboth cases, however, the confining pressure punctured the sleeve holdingthe core because too much of the rock face dissolved. For the 15% HClwith MgCl₂ fluid (FIG. 4C), the entry wormhole was much smaller and thewormholes 406 broke through to the opposite face in a timely fashion, 34minutes with 0.53 pore volumes to break through. These indicate that atlower injection rates, retarded acid with MgCl₂ was effective. Table 3provides the results of the same experiment conducted at 250° F., withsimilar comparative results both in data and facial dissolution as shownin FIG. 4D (for HCl alone) and FIG. 4E (for HCl with MgCl₂). A largeamount of core facial dissolution 402 and a developing conical wormholes404 occurred with HCl alone, while little facial dissolution and anarrower wormhole 406 resulted with the HCl and MgCl₂ mixture.

TABLE 3 Core break through characteristics at low acid injection ratesat 250° F. 15% HCl + Fluid => 15% HCl 19% MgCl₂ Injection rate (ml/min)0.4 0.4 Break through time >2:05 0:13 (h:mm) Pore volumes to break >40.34 through

In another example, rotating disk experiments were performed tocharacterize the relative surface reaction rates of acidic solutions.The experiment was conducted by spinning a marble or limestone disk, atambient temperature and 1250 rpm, in an acid formulation, andperiodically sampling the solution. The samples were then analyzed forthe calcium concentration as a function of time, which gives the rateconstant of calcite (CaCO₃) dissolution by hydrochloric acid containingsolutions. A decrease in rate constant indicates an acid retarding agentformulation whose surface reaction is retarded relative to hydrochloricacid alone, without any retarding agent. The plot in FIG. 5 illustratesslower dissolution rate, or slower rate of Ca²⁺ ions liberation overtime, for the 15% HCl solution containing MgCl₂ compared with unmodified15% HCl within 10 minutes. The results in FIG. 5 are a comparison of 15%HCl alone to 15% HCl mixed with 18.7% MgCl₂ retarding agent.

The foregoing description of the embodiments has been provided forpurposes of illustration and description. Example embodiments areprovided so that this disclosure will be sufficiently thorough, and willconvey the scope to those who are skilled in the art. Numerous specificdetails are set forth such as examples of specific components, devices,and methods, to provide a thorough understanding of embodiments of thedisclosure, but are not intended to be exhaustive or to limit thedisclosure. It will be appreciated that it is within the scope of thedisclosure that individual elements or features of a particularembodiment are generally not limited to that particular embodiment, but,where applicable, are interchangeable and can be used in a selectedembodiment, even if not specifically shown or described. The same mayalso be varied in many ways. Such variations are not to be regarded as adeparture from the disclosure, and all such modifications are intendedto be included within the scope of the disclosure.

Also, in some example embodiments, well-known processes, well-knowndevice structures, and well-known technologies are not described indetail. Further, it will be readily apparent to those of skill in theart that in the design, manufacture, and operation of apparatus toachieve that described in the disclosure, variations in apparatusdesign, construction, condition, erosion of components, gaps betweencomponents may present, for example.

Although the terms first, second, third, etc. may be used herein todescribe various elements, components, regions, layers and/or sections,these elements, components, regions, layers and/or sections should notbe limited by these terms. These terms may be only used to distinguishone element, component, region, layer or section from another region,layer or section. Terms such as “first,” “second,” and other numericalterms when used herein do not imply a sequence or order unless clearlyindicated by the context. Thus, a first element, component, region,layer or section discussed below could be termed a second element,component, region, layer or section without departing from the teachingsof the example embodiments.

Spatially relative terms, such as “inner,” “outer,” “beneath,” “below,”“lower,” “above,” “upper,” and the like, may be used herein for ease ofdescription to describe one element or feature's relationship to anotherelement(s) or feature(s) as illustrated in the figures. Spatiallyrelative terms may be intended to encompass different orientations ofthe device in use or operation in addition to the orientation depictedin the figures. For example, if the device in the figures is turnedover, elements described as “below” or “beneath” other elements orfeatures would then be oriented “above” the other elements or features.Thus, the example term “below” can encompass both an orientation ofabove and below. The device may be otherwise oriented (rotated 90degrees or at other orientations) and the spatially relative descriptorsused herein interpreted accordingly.

Although a few embodiments of the disclosure have been described indetail above, those of ordinary skill in the art will readily appreciatethat many modifications are possible without materially departing fromthe teachings of this disclosure. Accordingly, such modifications areintended to be included within the scope of this disclosure as definedin the claims.

What is claimed is:
 1. A multi-phase aqueous composition comprising: asurfactant; a first phase comprising water, an acid, and a water-solubleacid retarding agent; and a second phase selected from the groupconsisting of an immiscible organic phase, a gas, and combinationsthereof.
 2. The multi-phase aqueous composition of claim 1, wherein theacid is selected from the group consisting of hydrogen chloride,hydrogen bromide, hydrogen iodide, hydrogen fluoride, sulfuric acid,nitric acid, phosphoric acid, alkanesulfonic acids, arylsulfonic acids,acetic acid, formic acid, alkyl carboxylic acids, acrylic acid, lacticacid, glycolic acid, malonic acid, fumaric acid, citric acid, tartaricacid, and combinations thereof.
 3. The multi-phase aqueous compositionof claim 1, wherein the water-soluble acid retarding agent is selectedfrom the group consisting of a salt, urea or one if its derivatives, analpha-amino acid, a beta-amino acid, a gamma-amino acid, an alcohol withone to five carbons, a surfactant having a structure in accordance withFormula I, and combinations thereof:

in which R₁ is a hydrocarbyl group that may be branched or straightchained, aromatic, aliphatic or olefinic and contains from about 1 toabout 26 carbon atoms and may include an amine; R₂ is hydrogen or analkyl group having from 1 to about 4 carbon atoms; R₃ is a hydrocarbylgroup having from 1 to about 5 carbon atoms; and Y is an electronwithdrawing group.
 4. The multi-phase aqueous composition of claim 3,wherein the salt comprises: i) a cation selected from the groupconsisting of lithium, sodium, potassium, rubidium, cesium, beryllium,magnesium, calcium, strontium, barium, scandium, yttrium, titanium,zirconium, hafnium, vanadium, niobium, tantalum, chromium, molybdenum,tungsten, manganese, technetium, rhenium, iron, ruthenium, osmium,cobalt, rhodium, iridium, nickel, palladium, platinum, copper, silver,gold, zinc, cadmium, mercury, boron, aluminum, gallium, indium,thallium, tin, ammonium, alkylammonium, dialkylammonium,trialkylammonium and tetraalkylammonium, and ii) an anion selected fromthe group consisting of fluoride, chloride, bromide, iodide, sulfate,bisulfate, sulfite, bisulfite nitrate, alkanesulfonates, arylsulfonates,acetate, formate, and combinations thereof.
 5. The multi-phase aqueouscomposition of claim 1 wherein the surfactant is a foaming agent and thesecond phase comprises the gas.
 6. The multi-phase aqueous compositionof claim 5 wherein the multi-phase aqueous composition is in the form ofa foam.
 7. The multi-phase aqueous composition of claim 1, wherein thegas is selected from the group consisting of nitrogen, carbon dioxide,oxygen, helium, argon, hydrogen, methane, ethane, propane or butane, ora combination thereof.
 8. The multi-phase aqueous composition of claim 1wherein the second phase comprises the immiscible organic phase.
 9. Themulti-phase aqueous composition of claim 8, wherein the multi-phaseaqueous composition is in the form of an emulsion where the first phaseis a continuous phase and the second phase is a discontinuous phase andis stabilized by the surfactant.
 10. The multi-phase aqueous compositionof claim 9 wherein the surfactant is an ethoxylated nonionic surfactantof the structure RO(CH₂CH₂O)_(n)H, where R is an alkyl group of 6 to 18carbons, and 1≤n≤10.
 11. The multi-phase aqueous composition of claim 8,wherein the multi-phase aqueous composition is in the form of anemulsion where the second phase is a continuous phase and the firstphase is a discontinuous phase and is stabilized by the surfactant. 12.The multi-phase aqueous composition of claim 12 wherein the surfactantis a cationic surfactant of the structure [RNXYZ]⁺ A⁻, where R is analkyl chain of 10 to 18 carbons. X, Y and Z are selected from methyl,ethyl, hydroxyethyl or benzyl, wherein X, Y and Z can be the same ordifferent; and A is an anion selected from the group consisting offluoride, chloride, bromide, iodide, acetate, sulfate, alkylsulfonate,or arylsulfonate.
 13. A method comprising: providing a multi-phaseaqueous composition comprising: a surfactant; a first phase comprisingwater, an acid, and a water-soluble acid retarding agent; a second phaseselected from the group consisting of an immiscible organic phase, agas, and combinations thereof; and treating a subterranean formationfluidly coupled to a wellbore with an oilfield treatment fluidcomprising the multi-phase aqueous composition.
 14. The method of claim13, wherein the acid is selected from the group consisting of hydrogenchloride, hydrogen bromide, hydrogen iodide, hydrogen fluoride, sulfuricacid, nitric acid, phosphoric acid, alkanesulfonic acids, arylsulfonicacids, acetic acid, formic acid, alkyl carboxylic acids, acrylic acid,lactic acid, glycolic acid, malonic acid, fumaric acid, citric acid,tartaric acid, and combinations thereof.
 15. The method of claim 13,wherein the water-soluble acid retarding agent is selected from thegroup consisting of a salt, urea or one if its derivatives, analpha-amino acid, a beta-amino acid, a gamma-amino acid, an alcohol withone to five carbons, a surfactant having a structure in accordance withFormula I, and combinations thereof:

in which R₁ is a hydrocarbyl group that may be branched or straightchained, aromatic, aliphatic or olefinic and contains from about 1 toabout 26 carbon atoms and may include an amine; R₂ is hydrogen or analkyl group having from 1 to about 4 carbon atoms; R₃ is a hydrocarbylgroup having from 1 to about 5 carbon atoms; and Y is an electronwithdrawing group.
 16. The method of claim 15, wherein the saltcomprises: i) a cation selected from the group consisting of lithium,sodium, potassium, rubidium, cesium, beryllium, magnesium, calcium,strontium, barium, scandium, yttrium, titanium, zirconium, hafnium,vanadium, niobium, tantalum, chromium, molybdenum, tungsten, manganese,technetium, rhenium, iron, ruthenium, osmium, cobalt, rhodium, iridium,nickel, palladium, platinum, copper, silver, gold, zinc, cadmium,mercury, boron, aluminum, gallium, indium, thallium, tin, ammonium,alkylammonium, dialkylammonium, trialkylammonium and tetraalkylammonium,and ii) an anion selected from the group consisting of fluoride,chloride, bromide, iodide, sulfate, bisulfate, sulfite, bisulfitenitrate, alkanesulfonates, arylsulfonates, acetate, formate, andcombinations thereof.
 17. The method of claim 13 wherein the surfactantis a foaming agent and the second phase comprises the gas, wherein thegas is selected from the group consisting of nitrogen, carbon dioxide,oxygen, helium, argon, hydrogen, methane or ethane, or a combinationthereof.
 18. The method of claim 17 wherein the multi-phase aqueouscomposition is in the form of a foam.
 19. The method of claim 13 whereinthe second phase comprises the immiscible organic phase, and wherein themulti-phase aqueous composition is in the form of an emulsion where thefirst phase is a continuous phase and the second phase is adiscontinuous phase and is stabilized by the surfactant.
 20. The methodof claim 13, wherein the second phase comprises the immiscible organicphase, wherein the multi-phase aqueous composition is in the form of anemulsion where the second phase is a continuous phase and the firstphase is a discontinuous phase and is stabilized by the surfactant. 21.A method comprising: treating a subterranean formation fluidly coupledto a wellbore with an oilfield treatment fluid comprising a multi-phaseaqueous composition comprising: a surfactant comprising a foaming agent;a first phase comprising water, an acid, and a water-soluble acidretarding agent; and a second phase comprising a gas selected from thegroup consisting of nitrogen, carbon dioxide, oxygen, helium, argon,hydrogen, methane or ethane, or a combination thereof; wherein themulti-phase aqueous composition is in the form of a foam.
 22. The methodof claim 21, wherein the acid is selected from the group consisting ofhydrogen chloride, hydrogen bromide, hydrogen iodide, hydrogen fluoride,sulfuric acid, nitric acid, phosphoric acid, alkanesulfonic acids,arylsulfonic acids, acetic acid, formic acid, alkyl carboxylic acids,acrylic acid, lactic acid, glycolic acid, malonic acid, fumaric acid,citric acid, tartaric acid, and combinations thereof.
 23. The method ofclaim 21, wherein the water-soluble acid retarding agent is selectedfrom the group consisting of a salt, urea or one if its derivatives, analpha-amino acid, a beta-amino acid, a gamma-amino acid, an alcohol withone to five carbons, a surfactant having a structure in accordance withFormula I, and combinations thereof:

in which R₁ is a hydrocarbyl group that may be branched or straightchained, aromatic, aliphatic or olefinic and contains from about 1 toabout 26 carbon atoms and may include an amine; R₂ is hydrogen or analkyl group having from 1 to about 4 carbon atoms; R₃ is a hydrocarbylgroup having from 1 to about 5 carbon atoms; and Y is an electronwithdrawing group.
 24. The method of claim 23, wherein the saltcomprises: i) a cation selected from the group consisting of lithium,sodium, potassium, rubidium, cesium, beryllium, magnesium, calcium,strontium, barium, scandium, yttrium, titanium, zirconium, hafnium,vanadium, niobium, tantalum, chromium, molybdenum, tungsten, manganese,technetium, rhenium, iron, ruthenium, osmium, cobalt, rhodium, iridium,nickel, palladium, platinum, copper, silver, gold, zinc, cadmium,mercury, boron, aluminum, gallium, indium, thallium, tin, ammonium,alkylammonium, dialkylammonium, trialkylammonium and tetraalkylammonium,and ii) an anion selected from the group consisting of fluoride,chloride, bromide, iodide, sulfate, bisulfate, sulfite, bisulfitenitrate, alkanesulfonates, arylsulfonates, acetate, formate, andcombinations thereof.
 25. The method of claim 21, wherein themulti-phase aqueous composition is formed by: i) introducing thesurfactant and the first phase into the subterranean formation, and ii)separately introducing the gas into the subterranean formation forcontact with the surfactant and the first phase with sufficient energyto form the multi-phase aqueous composition in the form of a foam.